This invention relates to the recovery of hydrocarbons from subterranean formations and to compositions useful in such operations. More particularly, the invention relates to novel methods of stimulating subterranean formations, e.g., by fracturing and/or acidizing, to increase hydrocarbon production and diverting stimulation fluids away from water rich zones, thereby limiting stimulation fluid loss into such water rich zones, to novel methods for limiting the inflow of formation water, and to novel compositions useful in such methods.
In the recovery of hydrocarbons from subterranean formations, particularly in such formations wherein the wellbore also traverses water-bearing zones, the desire is to facilitate the movement of hydrocarbons to the wellbore so that the hydrocarbons may be pumped from the well. At the same time, there is a corresponding desire to limit the movement of formation water into the wellbore and production thereof In order to enhance the effectiveness of some of these methods for increasing hydrocarbon production, the proper placement of, for example, acidizing and/or fracturing fluids at the hydrocarbon zones and minimizing the loss thereof into the water zones is desirable.
In such fracturing operations, a fracturing fluid is hydraulically injected into a wellbore penetrating the subterranean formation and is forced against the formation strata by pressure. The formation strata or rock is forced to crack and fracture, and a proppant is placed in the fracture by movement of a viscous fluid containing proppant into the crack in the rock. The resulting fracture, with proppant in place, provides improved flow of the recoverable fluid, i.e., oil, gas or water, into the wellbore.
Fracturing fluids customarily comprise a thickened or gelled aqueous solution which has suspended therein xe2x80x9cproppantxe2x80x9d particles that are substantially insoluble in the fluids of the formation. Proppant particles carried by the fracturing fluid remain in the fracture created, thus propping open the fracture when the fracturing pressure is released and the well is put into production. Suitable proppant materials include sand, walnut shells, sintered bauxite, or similar materials. The xe2x80x9cproppedxe2x80x9d fracture provides a larger flow channel to the wellbore through which an increased quantity of hydrocarbons can flow, thereby increasing the production rate of a well.
A problem common to many hydraulic fracturing operations is the loss of fracturing fluid into the porous matrix of the formation. Fracturing fluid loss is a major problem. Hundreds of thousands (or even millions) of gallons of fracturing fluid must be pumped down the wellbore to fracture such wells, and pumping such large quantities of fluid is very costly. The lost fluid also causes problems with the function or technique of the fracture. For example, the undesirable loss of fluid into the formation limits the fracture size and geometry which can be created during the hydraulic fracturing pressure pumping operation. Thus, the total volume of the fracture, or crack, is limited by the lost fluid volume that is lost into the rock, because such lost fluid is unavailable to apply volume and pressure to the rock face.
Hydraulic fracturing fluids usually contain a hydratable polymer which thickens the fracturing fluid when it is chemically crosslinked. Such a polymer typically is-hydrated upon the surface of the ground in a batch mix operation for several hours in a mixing tank or other container, and crosslinked over a period of time to viscosity the fluid so that it is capable of carrying the proppant into the fracture. Natural polymers including polysaccharides, such as guar, have been used in this way.
One problem associated with the use of polysaccharides as viscosifiers for fracturing fluids is that the hydration and crosslinking process is time consuming and requires expensive and bulky equipment at the wellsite. Such equipment, and the associated personnel to operate it, significantly increase the cost of the fracturing operation. Further, once the polysaccharide is hydrated and crosslinked, it is not feasible to add additional polysaccharide to the solution, or to regulate the concentration of polysaccharide in the fracturing fluid in real time during the pumping of the job.
Another difficulty is that a large number of supplementary additives are required to use polysaccharides successfully, including for example: bactericides, antifoam agents, surfactants to aid dispersion, pH control agents, chemical breakers, enzymatic breakers, iron control agents, fluid stabilizers, crosslinkers, crosslirking delay additives, antioxidants, salt(s) and the like. These materials must be formulated correctly (which can be a difficult task), transported to the jobsiste, and then pumped and metered accurately during the execution of the fracturing treatment.
Another disadvantage associated with such polysaccharide-based fracturing fluids is that, when they are used as viscosifiers, they contain materials that concentrate in the formation during the course of the hydraulic fracturing treatment, reducing the production of hydrocarbons after the fracturing event. For example, during the course of a treatment, water from the fracturing fluid leaks into the formation leaving the polysaccharide behind. Guar concentrations in the fracture sometimes increase by as much as a factor of twenty as compared to the concentration of guar in the actual fracturing fluid.
Many fracturing fluid materials, therefore, when used in large concentrations, have relatively poor xe2x80x9cclean-upxe2x80x9d properties, meaning that such fluids undesirably reduce the permeability of the formation and proppant pack after fracturing the formation. Detailed studies of polysaccharide recovery in the field after hydraulic fracturing operations indicate that more than sixty percent of the total mass of polysaccharide pumped during the treatment maybe left in the fracture at the time gas or oil begins to be produced in commercial quantities. Poor clean-up is a problem.
Well productivity after fracturing increases dramatically as the amount of polysaccharide returned to the surface increases. Anything that reduces the permeability of the propped fracture to hydrocarbons is usually detrimental to the production of hydrocarbons from the well.
Other polysaccharides, such as hydroxyethylcellulose (xe2x80x9cHECxe2x80x9d), are sometimes believed to provide improved clean-up as compared to polysaccharide-based materials; however, HEC is known to form undesirable clumps or xe2x80x9cfish eyesxe2x80x9d during mixing. Further, HEC is limited to lower formation temperatures, and thus is not preferred for a wide variety of fracturing conditions.
To overcome the limitations of fracturing with natural or synthetic polysaccharides, some have suggested using relatively expensive materials as viscosity enhancers, such as viscoelastic surfactants. Fluids prepared from such materials are capable of carrying proppant into a fracture, but do not have many of the limitations of polysaccharide materials. Viscoelastic surfactants form micelles that are able to proceed into the reservoir rock, and then break up, allowing the components to be removed. Therefore, breaker materials are not customarily required, which reduces cost and improves cleanup of the fluid from the formation.
The problems encountered with viscoelastic surfactant-based fluids in the past, however, include relatively large fluid losses into formations in which they have been used. Micellar-type viscoelastic fluids have not been utilized widely in fracturing treatments of relatively low permeability formations because, among other reasons, materials have not been available that would enable the maintenance of a desired viscosity at temperatures above about 130xc2x0 F., which is less than the temperature at which most hydraulic fracturing operations are conducted.
Until recently, the use of such viscoelastic surfactant fluids has been restricted largely to operations in shallow, high permeability formations to control sand production either in conventional gravel packing operations or involving fracturing very close to the wellbore, such as in so-called xe2x80x9cfrac-and-packxe2x80x9d type operations. The cost of viscoelastic components has rendered them too expensive, in most cases, to utilize in normal fracturing treatments of a large size and high volume.
Use of viscoelastic surfactant fracturing fluids has been limited in many cases to formations that contain clays or otherwise need soluble salts for the specific purpose of inhibiting hydration of the clay materials. If such clay materials are allowed to hydrate, problems can occur, thus the need exists for a soluble salt that can inhibit the hydration of such clay-type materials. U.S. Pat. No. 5,551,516 to Norman et al. (xe2x80x9cNormanxe2x80x9d) discloses generally fracturing stimulation of high permeability formations, and more specifically, the use of surfactant-based fracturing fluids. However, Norman does not teach this invention, and in particular, does not teach application to low permeability formations. Further, Norman teaches the use of an organic activator, such as, for example sodium salicylate, which is not required in this invention.
Notably, low permeability formations present different fluid loss control challenges that typically are not addressed in fluids designed to work on high permeability formations. For example, solid fluid-loss-control additives, which are very effective in high permeability formations, have little or no utility in hydrocarbon zones of low permeability.
U.S. Pat. Nos. 4,725,372 and 4,615,825 (collectively xe2x80x9cTeotxe2x80x9d) specifically teach and define fluids used in treating the wellbore. This requires the use of heavy brines (e.g. greater than 12-15 lbs/gallon of brine). Heavy brines generally are not desirable in hydraulic fracturing of low permeability formations. Heavy brines can minimize fluid returns after the hydraulic fracturing treatment, adversely affecting cleanup and well productivity.
For example, fluid systems that operate effectively in ammonium chloride salts many times are frequently not compatible with much heavier calcium chloride, calcium bromide and zinc salt derived brines that typically are required for wellbore treatments. Therefore, fluids of a viscoelastic type designed for wellbore applications have not been directly useful in the past as reservoir treating fluids (sand control, acid fracturing, hydraulic fracturing, matrix acidizing, remedial scale inhibition treatments and the like) and vice-versa.
Acidizing is used to stimulate hydrocarbon production from a well. There are two types of acidizing treatments: (1) matrix acidizing and (2) fracture acidizing with the difference between them relating to injection rates and pressures. Fracture acidizing is acidizing at injection rates above fracture pressure. Fracture acidizing is used for creating cracks or fractures in the formation to increase the available flow area and thereby increase well productivity. Acidizing at injection rates below fracture pressure is termed matrix acidizing. Matrix acidizing is primarily used for damage removal and to restore the permeability to original reservoir permeability or higher. The damage is primarily skin damage caused by drilling, completion and workover fluids and precipitation of deposits from produced water or oil (such as scale). Removal of severe plugging in carbonate and sandstone formations can result in very large increases in well productivity. Oil well flow behavior is greatly affected by the geometry of radial flow into the wellbore. The pressure gradient, for example, psi per foot, is proportional to the flow velocity and is very small at large distances from the wellbore. At points close to the wellbore, the flow area is much smaller and the flowing pressure gradient is much higher. Because of this small flow area, any damage to the formation close to the wellbore, say within 20 feet thereof and sometimes within as little as 3 feet therefrom, may be the cause most of the total pressure draw down during production and thereby dominate well performance.
Because acidizing fluids do not discriminate between hydrocarbon and water bearing zones, an undesired result may be obtained wherein the production of formation water is increased. Thus, there is a need to direct acidizing fluids away from water bearing zones and preferably also limit the amount of formation water produced once the well is xe2x80x9cturned around.xe2x80x9d
Further, at the conclusion of a conventional hydraulic fracturing operation, it is necessary to bring back to the surface as much as possible of the hydraulic fluid components such as polymer, typically a galactomannan polysaccharide, broken polymer components, salts, typically ammonium chloride, potassium chloride and tetraethyl ammonium chloride, and fluid, typically a brine, pumped into the formation during treatment. This process of bringing the fluid back to the surface after the treatment is termed xe2x80x9cturning the well aroundxe2x80x9d. This process lasts from the moment fluid is begun to be brought back until the gas or oil is produced in sufficient quantities for sale. The well turnaround process can last from hours to several days. During this period, it has historically been possible to recover approximately one third of the polymer and fluid pumped during the hydraulic fracturing treatment.
In the case of low permeability (less than about 1 md) dry gas reservoirs (that is, gas reservoirs which produce hydrocarbons and little or no formation water), it is possible to dramatically improve the recovery of polymer and fluid during the well turnaround period by increasing the rate at which the fluids are brought back to the surface. This has been documented in two published field studies. SPE 31094 (D. Pope, L. Britt, V. Constien, A. Anderson, L. Leung, xe2x80x9cField Study of Guar Removal from Hydraulic Fractures: presented at the SPE International Symposium on Formation Damage Control, Lafayette, La., Feb. 14-15, 1995) provided the first demonstration that increased flowback rate results in increased polymer recover which results in increased well productivity. This was taken further in SPE 36468 (A. J. Anderson, P. J. N. Ashton, J. Lang and M. L. Samuelson, xe2x80x9cProduction Enhancement Through Aggressive Flowback Procedures in the Codell Formationxe2x80x9d presented at the SPE Annual Technical Conference and Exhibition, Denver, Colo., Oct. 6-9, 1997) where polymer recovery was increased to more than 60% of the amount pumped during the treatment and 90 day cumulative production was increased by more than 50% over those of offset wells with less aggressive flowback rates. Similar results have been observed in other low permeability dry gas wells. (See, for example, SPE 30495, P. R. Howard, M. T. King, M. Morris, J. P. Feraud, G. Slusher, S. Lipari, xe2x80x9cFiber/Proppant Mixtures Control Proppant Flowback in South Texasxe2x80x9d presented at the SPE Annual Technical Conference and Exhibition, Dallas, Tex., Oct. 22-25, 1995.)
The flowback pattern from this type of formation is very distinctive. This is illustrated in FIG. 10. This figure presents a graph of the concentration of the polymer, in this case guar, in samples of fluid flowed back to the surface after the hydraulic fracturing treatment of a dry gas well as a function of the time between the start of the flowback and when the sample was collected. The concentration of polymer in these samples is equal to or greater than the concentration of guar pumped during the treatment and is relatively constant over time. This behavior continues for months after the turn around period is over and the well is in production.
However, in recent studies relating to oil wells, we have determined and demonstrated that the inflow of formation water during the well turn around period is detrimental to the ability to maximize the polymer recovered after a hydraulic fracturing treatment of a gas or oil well and to efforts to maximize well productivity. As a result, we have identified that there is a need to control the inflow of this formation water during the well turn around stage in order to be able to maximize well productivity.
A need exists for a surfactant fluid that economically can increase hydrocarbon production, limit formation water production, resist fluid loss into the formation, direct fluids away from water bearing zones, and preserve the component balance of the fluid mixture. A fluid that can achieve the above while improving the precision with which fluids are delivered, and reduce equipment or operational requirements, would be highly desirable.
It has been discovered that a viscous surfactant fluid may be used advantageously in many different fracturing applications to achieve results not previously believed possible using such fluids. In particular, this invention is effective in increasing hydrocarbon production following hydraulic fracturing. Further, these methods may be employed to limit formation water production after fracturing, which assists in improving the percentage of hydrocarbons recovered once a well is put back on production after fracturing.
Other advantages of the methods of this invention include that it assists in resisting fracturing fluid loss into the subterranean formation by directing fluids away from water-bearing zones, thereby saving money and preserving the component balance of the fracturing fluid mixture. It is also an advantage of this invention that it is possible to reduce the equipment requirements in mixing and pumping fracturing fluids at the wellsite, and improve operational efficiency in fracturing wells. This invention can be utilized to save operating expense and to improve the precision with which fluids may be delivered into the wellbore during fracturing.
The inventions contained in U.S. patent application Ser. No. 08/727,877, entitled Methods of Fracturing Subterranean Formations, filed Oct. 7, 1996, and 08/865,137, entitled Methods for Limiting the Inflow of Formation Water and for Stimulating Subterranean Formations, filed May 29, 1997, both of which have been previously incorporated by reference in their entirety, and are assigned to the assignee of the present invention, centered on surfactants which contained micelles, the micelles having a structure that contributes to the increased viscosity of the fluid. Specific embodiments therein were viscoelastic surfactants which formed worm-like micelles. Continuing the development of the inventions of these U.S. patent applications, we have found that worm-like micelles are only one type of micelles which form a structure in an aqueous environment that contributes to the increased viscosity of the fluid. Other structures are (1) closely packed spherical micelles, (2) serpertine multilayered structures, (3) entangled or interlocking multiple elongated micelle structures and (4) other structures which defy simple word characterization and will be referred to as xe2x80x9caggregates.xe2x80x9d Please note that xe2x80x9cmicellexe2x80x9d includes vesicles. We have also found other types of surfactants, not necessarily viscoelastic surfactants, possessing these characteristics. Those identified in the aforementioned patent applications are amines (nonionic surfactant) and amine salts and quaternary amine salts (cationic surfactants).
The surfactant component of the viscous fluid of the present invention comprises at least one surfactant selected from the group consisting of cationic, anionic, zwitterionic (including amphoteric), nonionic and combinations thereof, wherein the surfactants alone or in combination are capable of forming micelles which form a structure in an aqueous environment that contribute to the increased viscosity of the fluid (hereinafter called xe2x80x9cviscosifying micellesxe2x80x9d) and wherein the viscous fluid loses its viscosity when in contact with hydrocarbons. The viscous fluids of the present invention are stable to temperatures in excess of 130 degrees xc2x0 F., preferably at least 150xc2x0 F., more preferably at least 175xc2x0 F. and yet more preferably at least 200xc2x0 F., and are also shear stable showing little to no shear hysteresis.
In one embodiment, the invention comprises a method of reducing fluid loss into a relatively low permeability formation during fracturing by providing a viscous fracturing fluid comprising a thickening amount of at least one surfactant, each such surfactant comprising a surfactant ion having a hydrophobic first portion chemically bonded to an ionic hydrophilic second portion, wherein the surfactant spontaneously forms micelles having a structure that contributes to the increased viscosity of the fluid when the concentration is higher than the critical micellar concentration. The viscous fracturing fluids are stable at temperatures greater than 130 degrees xc2x0 F., preferably at least 150xc2x0 F., more preferably at least 175xc2x0 F. and yet more preferably at least 200xc2x0 F., and are capable of selectively forming, changing structure or disbanding depending upon the polarity of the surrounding fluid in the formation. For example, these fluids maintain their viscosity in the presence of water, but lose their viscosity when in contact with hydrocarbons.
The fluid is pumped, for example, into a relatively low permeability formation at a pressure sufficient to fracture the formation, the relatively low permeability formation having a fracture face engaged by the fluid during pumping. Typically, the formation comprises at least one largely hydrocarbon-bearing zone and at least one largely aqueous zone.
The viscosity of the fluid within the hydrocarbon-bearing zone is decreased, while the viscosity of the fluid within the aqueous zone is maintained. Further, the amount of viscous fluid lost into the fracture face is reduced, whereby a greater volume of viscous fluid is available for fracturing the relatively low permeability formation, and increasing the ratio of fracture size per unit volume of viscous fluid pumped into the wellbore.
In other methods, the invention includes enhancing the cleanup of viscous fracturing fluid from the well, or in some cases flowing back fluid from the wellbore, wherein hydrocarbon production upon flowing back fluid from the wellbore is increased.
The viscosity of fluid within the at least one aqueous zone of the subterranean formation is maintained by presence of the viscosifying micelles in that zone of the formation, and viscosity of the fluid within the at least one hydrocarbon-bearing zone is depleted by the disbanding or structural change of the micelles to a structure which does not contribute to increased viscosity of the fluid.
In many cases, the maintenance of the viscosifying micelles within aqueous zones contributes to an increase in hydrocarbon production from the wellbore upon flowing back fluid from the wellbore following fracturing.
In another embodiment, a method of reducing the production of water from a subterranean formation subsequent to fracturing the subterranean formation is shown. This method is directed to providing an hydraulic fracturing fluid comprising an aqueous medium, an effective amount of a water-soluble salt, and an effective amount of a thickener in the fluid, generating a viscous fluid comprising viscosifying micelles; and pumping the viscous fluid comprising viscosifying micelles through a wellbore and into a formation at a pressure sufficient to fracture the formation. The formation may have an aqueous zone containing a significant amount of water, and a hydrocarbon zone. The viscosifying micelles in the viscous fluid within the hydrocarbon zone undergo a structural change or break down, thereby decreasing the viscosity of the fluid within the hydrocarbon zone to form a thinned fluid. The thinned fluid is then removed from the hydrocarbon zone of the formation. The viscosifying micelles in the water zone are more stable, and a reduction in the amount of water produced from the formation during the removing step is observed. Further, the advantage of increasing the production of hydrocarbons from the subterranean formation is realized.
In another method of the present invention, the formation is fractured by providing an aqueous hydraulic fracturing fluid comprising an aqueous medium, an effective amount of a water-soluble salt to effect formation stability, particularly clay stability, and at least one thickener selected from the group of surfactants consisting of cationic, anionic, zwitterionic (including amphoteric), nonionic and combinations thereof, wherein the surfactant or surfactants are capable of forming viscosifying micelles in an aqueous environment.
This method includes the steps of generating a viscous fluid comprising viscosifying micelles, pumping the viscous fluid comprising such micelles through the wellbore and into the formation at a pressure sufficient to fracture the formation. The micelles enter the water zone and the hydrocarbon zone and a fracture is accomplished. The micelles undergo a structural change or disband within the fluid in the hydrocarbon zone, thereby decreasing the viscosity of the fluid within the hydrocarbon zone. The well is flowed back, and hydrocarbons are produced from the subterranean formation. Significantly, there is a reduction in the amount of water produced from the subterranean formation during the removing step.
In one method, a procedure of fracturing a subterranean formation below the surface of the ground is disclosed using a viscous fracturing fluid that does not require prolonged hydration above the ground surface, resulting in a more efficient and less costly procedure. In this way, the fluid is prepared by simply continuously metering a concentrate at the ground surface into a blender, the concentrate comprising a thickening amount of at least one surfactant comprising a surfactant ion having a hydrophobic first portion chemically bonded to an ionic hydrophilic second portion. When a cationic viscosifying surfactant, such as a quaternary amine, is used alone, a counter-ion having a component capable of associating with the surfactant ion and forming a viscous fluid and a functionally effective amount of water are added. Mixing of the concentrate with the counter-ion and water above the ground surface is performed at the blender to instantly form a viscous fracturing fluid containing viscosifying micelles, which is simultaneously pumped below the surface of the ground into a wellbore.
The present invention provides a method of limiting the inflow of formation water during and after a well turn around to maximize the recovery of the fracturing fluid and components thereof after a hydraulic fracturing treatment of a formation having a hydrocarbon zone and a water-bearing zone, the method comprising:
step for selectively blocking the pore structure in the water-bearing zone at the formation face and not blocking the pore structure of the hydrocarbon zone at the formation face;
performing a hydraulic fracturing treatment using a fluid capable of transporting a proppant into a fracture; and
turning the well around to recover the fluid and components thereof,
wherein the step for selectively blocking forms a plug of a viscous fluid in the pore structure of the water-bearing zone at the formation face and
wherein the viscous fluid includes at least (1) at least one surfactant capable of forming viscosifying micelles in an aqueous environment, (2) a water-soluble salt to effect formation stability, particularly clay stability, and (3) an aqueous carrier fluid in which the at least one surfactant forms the viscosifying micelles.
The term xe2x80x9cwater-bearing zonexe2x80x9d means any portion of the formation that is capable of producing water during the turn around period. Accordingly, the term xe2x80x9cwater-bearing zonexe2x80x9d includes a hydrocarbon-bearing zone that has a sufficiently high water saturation such that the water is mobile and produced during the turn around period.
The components of the fluid being recovered include the polymer, typically a galactomannan polysaccharide, broken polymer or polymer fragments and monomers thereof, salts, typically ammonium chloride, potassium chloride and tetraethyl ammonium chloride, and fluid, typically brine. The proppant carried by the fracturing fluid substantially remains in the fracture created during the fracturing process.
In another aspect of the present invention, there is provided a method of acidizing, including acid fracturing and matrix acidizing, a formation having a hydrocarbon zone and a water-bearing zone, the method comprising:
step for selectively blocking the pore structure in the water-bearing zone at the formation face to selectively retard migration of acid into the water-bearing zone and allow migration into the hydrocarbon zone; and
injecting acid into the formation,
wherein the acid is diverted from the water-bearing zone to the hydrocarbon zone as a result of selectively blocking the pore structure in the water-bearing zone at the formation face and
wherein the viscous fluid includes at least (1) at least one surfactant capable of forming viscosifying micelles in an aqueous environment, (2) a water-soluble salt to effect formation stability, particularly clay stability, and (3) an aqueous carrier fluid in which the at least one surfactant forms the viscosifying micelles.
When the water-bearing zone contains a residual amount of hydrocarbon residues, these methods further comprise injecting a mutual solvent prior to the step for selectively blocking. The mutual solvent is preferably selected from the group consisting of low molecular weight esters, ether and alcohols, and more preferably, the mutual solvent is a low molecular weight ether, for example, ethylene glycol monobutyl ether.